scale evaluating water constituents to understand which

ScaleEvaluating Water Constituents To Understand Which

Constituents Encourage Scale Formation Downhole And How To Utilize Scale Inhibitors And Dissolvers

Economically To Reduce Build-Up

Stephen Vance

What is scale?

• They are solids that block pipes, pore throats, etc.

• They are mainly inorganic minerals that do not like to dissolve in water

Why does this happen?

• It can happen in several ways

• Water incompatibility

– Fresh water usually has high amount of insoluble anions

• Sulfates – SO42-

• Carbonates and bicarbonates – CO32- and HCO3

-

– Indicated by a high pH

Why does this happen? (cont.)

• Water in the shale formation usually has high amounts of cations

• Calcium – Ca2+

• Magnesium – Mg2+

• Barium – Ba2+

• Strontium – Sr2+

• Iron – Fe2+


• These connate waters mixed with fresh waters can upset the equilibrium of the solvated ions

• When one type of cation sees a particular anion, their ability to remain apart is threatened

– Ca2+(aq) + CO32- (aq) CaCO3(s)

– Ba2+(aq) + SO42-(aq) BaSO4(s)

Crystal Lattice


• If there is no mixing of fresh water with produced water, the solubility of the ions are dictated by temperature and pressure

– Under pressure ions stay dissolved

– Usually scale will form when there is a drop in pressure

– Equations of state are used to determine if scale will form


• Temperature

– Calcite and siderite scale out when temperature goes up

– Barite scales out when temperature goes down

– Celestite and gypsum scale varies with temperature

• Solubility goes up with temperature, then goes down

Water Analysis

Water Analysis (cont.)

Red line shows saturation index

Blue line shows pounds of scale per thousand barrels of water

Water Analysis (cont.)

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

30 40 50 60 70 80 90 100 110

Satu

rati

on

ind

ex,

Bar

ite

Temperature, F

Barite Saturation Index vs. Temperature (F)Inhibitor Concentration Risk Curves

SIBar+10 mg/L Inh

SIBar+3 mg/L Inh

SIBar+1.0 mg/L Inh

SIBar+0.3 mg/L Inh

SIBar+0.0 mg/L Inh

Water Sample SICal

Calcite and Aragonite

• Calcium carbonate

CaCO3

• A very common

scale

• Acid soluble

• Solubility goes up

when pH goes down

• Solubility goes down with increasing heat

Gypsum

• Calcium Sulfate

CaSO4

• Acid insoluble

• Can be chelated with things like EDTA

• Can be converted then acidized

Barite

• Barium sulfate

BaSO4

• Acid insoluble

• Proportionally soluble with increasing heat

• Usually mechanical removal is only method

Siderite

• Ferrous carbonate

FeCO3

• Usually caused by corrosion by-product

• Same issues as calcite

• Can be useful in corrosion protection

Iron Sulfide

• FeS

• Product of H2S and ferrous iron

• THPS or Acrolein is used to get rid of it

• Needs time and surfactants help get through the oil wet solids

• Acrolein is very dangerous

How to prevent scale

• Crystal Inhibitors– Phosphate Esters

• Example: citric acid phosphate

• Heat restrictions

• 175 °F?

• o-Phosphate (orthophosphate can cause calcium phosphate)

• Apatite

• Acid insoluble

Kelland, Malcom A. Production Chemicals for the Oil and Gas Industry. Boca Raton: Taylor and Francis Group, 2009. Print.

How to prevent scale (cont.)

– Organophosphonates

• Examples: ATMP, DETA, BHMT, AEEA

• Always though of them like the 300 Spartans

• More heat tolerant compared to phosphate esters

• Calcium tolerance can be an issue

–Bonds with calcium to make a precipitate itself

» BHMT is better at avoiding that than DETA



– Organophosphonates• N,N’-bis(3-aminopropyl)ethylene diamine

phosphonate is claimed to be better at barite scales

• Can be overwhelmed with high brine concentrations

• pH is critical

–Keep around 4.5-7

– Loses effectiveness above 7

–Chloride corrosion has been suspected



• Crystal Modifiers (polymers)– Polycarboxylates are the most common in our field

• Examples: Salts of polyacrylic acid, polymethacrylic acid, and polymaleic acid

– Hard to deliver

– Heat tolerant

– Does not stop precipitation of the insoluble ions• Stops the adherence of the precipitated solids

– Not overwhelmed by high salt brines

– Usually can’t be tracked without tags


Solvent Package

• Most scale inhibitors are water based

• Water can evaporate in hot wells

• Ethylene glycol, butyl cellusolve, etc. have higher boiling points

– Keep scale inhibitors in solution

– Usually adds ~20% more to cost

Chemical Delivery

• Capillary String

• Costly ($1-$2/foot installed)

• Best way to ensure chemical delivery

• There are strings that can go past packers

• Very good for ESPs and downhole scale inhibition

• Have to ensure chemical is cap string approved

Chemical Delivery (cont.)

• Downhole

• Gas Lift

• Always inject on side of gas injection

• Dry gas dehydrates chemical more than wet gas

• Packers – only treat to bottom gas lift valve

• Best to use a 50-200’ stinger of capillary tubing


• Backside no gas lift

• If flowing or packer in place, unable to treat down hole

• No idea of life cycle of chemical– Could be in for a few hours

– Could be in for days

– When does it get around?

– Have to test residuals

– Coupon data


• If well is surging on backside, the chemical could come out the backside and not ever get to tubulars

• Backside flush with produced fluid to ensure delivery

Scale Squeeze

• Not preferred

• Squeezing is not correct name for lateral wells

– Spot is more appropriate nomenclature

– Assumed to go to most water bearing zone

– More than likely goes to least pressured zone

• Costly (Ex. $6500/spot)

Scale Squeeze (cont.)

• Tagged polymers are best to use in spot

– Monitor residuals by ICP or tag

– Once levels get below usually 5 ppm, squeeze is needed again

• Most of the squeezed chemicals come out in the first months after squeeze

– Usually need to redo after six months

Scale Squeeze (cont.)

Solids AnalysisWhat if you don’t prevent scale?

How to remove scale

• Calcite (calcium carbonate)

– Acid

– Mainly HCl, because HF can cause CaF2(S)

• Corrosive

• Time to shut in and react

– Acetic Acid usually too weak and slow

– THPS could be used but not really its purpose

– Surfactant is used sometimes to wash oil off


How to remove scale (cont.)

• Gypsum (calcium sulfate)

– EDTA salts can be used to chelate it which dissolves it

• Need high pH (~8) to make the EDTA functional

– Can be converted to be acidized

• Use of strong bases are used to make calcium sulfate into calcium carbonate or calcium hydroxide

• Then acid is used to dissolve it

How to remove scale (cont.)

• Barite (barium sulfate)

– Basically has to be mechanically milled out

– Chelation and conversion can’t really be effective

– Costs to chemically remove barite usually is more than removing it mechanically

– Usually present in surface equipment

– Diethylenetriamine pentaacetic acid (DTPA) has been used at a pH of 12 or higher

– Best bet is to prevent it

Chelation Dissolution

M = Divalent ion like Ca2+ or Ba2+

Dynamic Tube Block Test

• Scale chemicals are best tested by dynamic tube block apparatus

• Mixes a synthetic brine to make a representative fluid that may be encountered

• If scale inhibitor does not work tube scales up

– This is evident by pressure going up

• If scale inhibitor works, the fluids will not scale

– This is evident if pressure stays low

Dynamic Tube Block Apparatus

Cost Exercise

• Scale inhibitor cost $8/gallon

• Recommended rate 100ppm

• Well makes 650 barrels of water a day

• That would be ~11 quarts a day of chemical

• ~$22 a day or ~$8000 a year

• Usual replacement of a string of tubing is ~$30,000

Phosphate Residuals

• Ex: 5 ppm of phosphorus– Phosphorus 30.97 g/mol

– DETA phosphonate 573.20 g/mol

– There are five in DETA, so weight percent is [(30.97 x 5)/573.20] x 100 = 27.0% Phosphorus

– Reciprocal factor is 3.70

– So 5 ppm P x 3.70 = 18.5 ppm of DETA phosphonate

– Minimum inhibition concentration (MIC) may be as low as 5 ppm DETA therefore GOOD

QUESTIONS OR COMMENTS?

scale evaluating water constituents to understand which

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